Subsurface formation drilling to recover hydrocarbons is well known in the art. The equipment for such subsurface formation drilling typically comprises a drill string having a rotary drill bit attached thereto that is lowered into a borehole. A rotary table or similar device rotates the drill string, resulting in a corresponding rotation of the drill bit. The rotation advances the drill bit downwardly, causing it to cut through the subsurface formation (e.g., by abrasion, fracturing, and/or shearing action). Drilling fluid is pumped down a channel in the drill string and out the drill bit to cool the bit and flush away debris that may have accumulated. The drilling fluid travels back up the borehole through an annulus formed between the drill string and the borehole.
Many types of drill bits have been developed, including roller cone bits, fixed cutter bits (or “drag bits”), and the like. For each type of drill bit, several patterns of cutting elements (or “cutters”) are possible, including spiral patterns, straight radial patterns, and the like. Different types of cutting elements have also been developed, including milled cutting elements, tungsten carbide inserts (“TCI”), polycrystalline-diamond compacts (“PDC”), and natural diamond cutting elements. The selection of which drill bit, cutting element type, and cutting element pattern to use for a given subsurface formation can depend on a number of factors. For example, certain combinations of drill bit, cutting element type, and cutting element pattern drill more efficiently and effectively in hard formations than others. Another factor is the range of hardness encountered when drilling through the different formation layers.
One common pattern for drill bit cutting elements is to arrange them in a spiral configuration, an example of which is shown in FIGS. 1A-1B. As can be seen, a spiral pattern drill bit 100 is composed of several sections, including a bit body 102, a shank 104, and a threaded connector 106 for connecting the drill bit 100 to a drill string. Flats 108 on the shank 104 allow a tool, such as wrench, to grip the drill bit 100, making it possible (or at least easier) to screw the drill bit 100 onto the drill string. Blades 110a, 110b, 110c, 110d, 110e, and 110f are formed on the drill bit 100 for holding a plurality of cutting elements 112. The cutting elements 112 include superabrasive faces that usually have identical geometries (i.e., size, shape, and orientation), although different positions and/or cutting angles on the blades 110a-f. Also visible are drill fluid outlets 114 that conduct the drilling fluid out of the drill bit 100, carrying away any debris and cuttings that may have accumulated.
In the spiral configuration and other radial configuration drill bits, the cutting elements 112 are placed at selected radial positions with respect to a central longitudinal axis A. In addition, the positions of the cutting elements 112 on one blade 110a-f are staggered relative to the positions of the cutting elements 112 on another blade 110a-f. The result is that a cutting surface of one cutting element 112 overlaps the cutting surface of at least one other cutting element 112 in their cutting profiles, which is the area outlined by the cutting surfaces when the cutting elements are rotated onto the same radial plane. Thus, each cutting element 112 removes a lesser volume of material than would be the case if it were positioned so that no overlapping occurred.
FIGS. 2A-2C illustrate the overlap via a segment of a drill bit's cutting profile 200 for the drill bit 100. Note that the portions of the blades 110a-f shown in FIGS. 2A-2C have been flattened out in order to more clearly illustrate the shortcomings of existing drill bits. Those having ordinary skill in the art will recognize that, in practice, the blades of a drill bit frequently have some degree of curvature.
As can be seen, the profile segment 200 is composed of several individual cutting profiles 202a, 202b, 202c, and 202d representing the various cutting elements 112 (see FIG. 1) on the blades 110a-f. The cutting profiles 202a-d show the area outlined by the cutting surfaces of the cutting elements 112 when they are all rotated onto the same radial plane. Thus, the profile segment 200 may be shared by the cutting elements 112, denoted herein by cutting profiles 202a, 202b, 202c, or 202d, even though the cutting elements 112 may physically reside on different blades 110a-f, have different radial positions on the blades 110a-f, and follow different paths in the subsurface formation as the bit is rotated. This arrangement ensures substantially complete coverage of the bottom hole as the bit is rotated during the drilling process.
The overlap can be seen in more clearly FIG. 2B, where the cutting surfaces represented by the first and second cutting profiles 202a and 202b overlap when rotated onto the same radial plane. Similarly, the cutting surfaces represented by the second and third cutting profiles 202b and 202c overlap when rotated onto the same plane. Likewise, the cutting surfaces represented by the third and fourth cutting profiles 202c and 202d overlap when rotated onto the same plane.
The overlap helps provide greater coverage for the borehole bottom, but can result in a specific wear pattern that, depending on the location of the wear, may drastically blunt the cutting elements 112, causing severe reductions in ROP. In the specific example shown, the overlap occurs mainly on the sides 204 of the cutting profiles 200a-d. As a result of the overlaps, the cutting element density in those areas 204 is necessarily greater than the density in the tip regions 206 of the cutting profiles 200a-d. Consequently, the cutting elements, as shown by the individual cutting profiles 202a-d along the segment of the bit's profile 200, tend to wear down more quickly in the tip regions 206, which happen to be the most mechanically efficient portion of the cutting element. This is indicated by the cutting profiles 202a′-d′ of FIG. 2C.
Accelerated or pronounced wear in the most mechanically efficient portions of the cutting elements is not a great hindrance in comparatively soft formation materials, where rates of penetration (ROP) are usually higher and less energy is usually required to fail the rock being drilled. However, for hard formations, the tip regions of the cutting surfaces are the most effective portions for shearing (in the case of shale, sandstone, and siltstone) or fracturing (in the case of limestone and dolomite) the rock being drilled. For these subsurface formations, a drill bit where the cutting elements exhibit accelerated cutter tip wear (based on the cutting profile) can significantly reduce the ROP. This wear pattern can also minimize a drill bit's effectiveness at combating damaging vibrations, specifically lateral vibrations and bit whirl, due to the resulting bottomhole pattern that is created as a result of the wear. Stabilization forces that normally act to re-stabilize the bit at the initiation of an off-center movement and/or rotation are minimized, making bits with pronounced cutter tip wear patterns prone to intense vibrations.
Thus, despite certain advances made in the industry, there remains a need for a drill bit having an improved cutting element arrangement that will permit the bit to drill effectively at good or economical ROPs, and provide increased stability and enhanced mechanical efficiency as wear occurs, especially in hard formations, and in deep harsh drilling environments, where the time and expense needed to retrieve and replace ineffective and un-stable drill bits substantially increase overall drilling operational costs.